Optimized production via geological mapping

ABSTRACT

Optimizing deposit production in a well includes localizing the low resistivity fluid deposits in a geological formation. Once the deposits are mapped, production of the fluid deposit from the geological formation is optimized based on the localizing. The optimization may include adjustment of at least one of a drilling parameter or a production parameter.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims the benefit of priority to provisionalapplication Ser. No. 62/062,451, filed Oct. 10, 2014, which isincorporated herein by reference in its entirely.

BACKGROUND

The easy to access and produce hydrocarbon resources are being depletedleaving more difficult wells to access and produce. Meeting the world'sgrowing demand for hydrocarbons resulted in the development of advancedrecovery procedures, often referred to as complex recovery completionsand production techniques. These methods may include Steam AssistedGravity Drainage (SAGD), Thermal Assisted Gravity Drainage (TAGD), Toeto Heal Air Injection (THAI), Vaporized Hydrocarbon Solvent (VAPEX)production and Fire Flooding. These techniques address the mobilityproblem of the heavy oil wells by thermally and/or chemically alteringthe viscosity of the bitumen to allow for easy extraction. While each ofthe complex completion techniques offers a novel approach to heavy oilextraction, their success may rely on the difficult process of preciseplacement of wellbores with respect to near-by geological structures.

One difficult scenario includes local deposits that have the potentialto cause steam to break through, resulting in a non-optimal steamchamber. In this case, as steam is injected from the injector well, itbreaks through above or below the deposits and results in insufficientheating of bitumen and, thus, reduction in production.

In one solution, producer wells are placed using resistivity or gammalogs to detect formation layering from a distance. In this case, adistance to nearby layering is used to optimally place the producer wellin the reservoir by geosteering the drilling. After the producer well isplaced, the injector well is placed with respect to the producer wellusing ranging devices that can measure the relative distance anddirection between the two wells.

Well-known commercial approaches for this technique are based onrotating magnets (e.g., U.S. Pat. No. 5,589,775) or magnetic guidance(U.S. Pat. No. 5,923,170) that utilize both wellbores for ranging. Mostof these approaches, however, are undesirable in that they use twodifferent crews (i.e., wireline and logging while drilling (LWD)), whichis not cost effective. One prior magnetic approach is based on a singlewell system where both the transmitter and the receivers are downhole.This approach, however, is based on absolute magnetic field measurementfor distance calculation (U.S. Pat. No. 7,812,610) that does not producereliable results due to variations of the current on the target pipe.

Additionally, the prior art techniques typically place the injector wella fixed distance above the producer well. The selection of the fixeddistance may be made heuristically without considering geological andpetrophysical variations. This may result in placement of the injectorwell at non-optimal positions and reduction in volume of accessiblehydrocarbons.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a flowchart showing a method for optimizing production offluid deposits using geological mapping, according to various examples.

FIG. 2 is a cross-sectional diagram showing a geological formationhaving a fluid deposit to be mapped using various embodiments of alocalizing method from a producer well, according to various examples.

FIG. 3 is a flowchart showing an embodiment of the method forlocalization using electromagnetic (EM) resistivity measurements,according to various examples.

FIG. 4 is a flowchart showing an embodiment of the method forlocalization using current leakage measurement, according to variousexamples.

FIG. 5 is a flowchart showing another embodiment of the method forlocalization using current leakage measurement, according to variousexamples.

FIG. 6 is a flowchart showing another embodiment of the method forlocalization using current leakage measurement, according to variousexamples.

FIG. 7 is a flowchart showing another embodiment of the method forlocalization using current leakage measurement, according to variousexamples.

FIG. 8 is a cross-sectional diagram showing a geological formation withan embodiment of an SAGD steam chamber, according to various examples.

FIG. 9 is a flowchart showing an embodiment of a method for optimizingproduction of a fluid deposit, according to various examples.

FIG. 10 is a flowchart showing another embodiment of the method foroptimizing production of the fluid deposit, according to variousexamples.

FIG. 11 is a flowchart showing another embodiment of the method foroptimizing production of the fluid deposit, according to variousexamples.

FIG. 12 is a cross-sectional view of a geological formation in which ageosteering embodiment of the optimization method is used around adeposit, according to various examples.

FIG. 13 is a cross-sectional view of a geological formation in whichvarious casing embodiments of the optimization method are used near adeposit, according to various examples.

FIG. 14 is a diagram of a wireline system embodiment, according tovarious examples.

FIG. 15 is a diagram of a drilling rig system embodiment, according tovarious examples.

DETAILED DESCRIPTION

The embodiments described herein include two steps: localization andmeasurement of low resistivity fluid deposits and optimization ofproduction with the given geology information. The localization andmeasurement may be performed through downhole or surface resistivitymeasurements owing to the low resistivity nature of the deposits. Thelocalization and measurement step may also be referred to as mapping ofthe deposits in a geological formation.

The optimization may be performed using multiple methods. For example,the drill string (e.g., drill bit) of the injector or producer wells maybe geosteered away from the deposits in a three dimensional fashion(e.g., laterally and/or vertically). In another optimization embodiment,the slots and/or seams of the well casing may be adjusted based on thenear-by deposits. Both types of optimization may be assisted by steamchamber or geo-steering models that incorporate the local geology anddrilling performance related information.

The fluid deposits referred to herein include a low resistivity fluiddeposit. Low resistivity fluid deposits may be characterized bymeasuring how strongly the fluid opposes the flow of electric current. Alow resistivity fluid deposit may be defined as any fluid having anelectrical resistance of less than 300 Ohms which includes mosthydrocarbons. The low resistivity fluid deposit may be referred to assimply a fluid, a deposit, or a fluid deposit and is assumed herein tobe low-resistivity.

FIG. 1 is a flowchart showing a method for optimizing production offluid deposits using geological mapping, according to various examples.In box 101, a method for localizing and measuring the deposits in ageological formation is initially used. This step maps the size andlocation of the deposits. Various embodiments for localizing andmeasuring the deposits are illustrated in FIGS. 2-7 and discussedsubsequently.

Once the deposits are mapped, production of the deposits may then beoptimized in box 103 by adjusting at least one of a drilling parameteror a production parameter. Various embodiments for optimizing productionof the deposits are illustrated in FIGS. 8-13 and discussedsubsequently.

FIG. 2 is a cross-sectional diagram showing a geological formationhaving a fluid deposit to be mapped using various embodiments of alocalizing method from a producer well, according to various examples.It is noted here that the variations that are included in thisillustration are not necessarily used together and they are showntogether mainly for the sake of contrasting them with respect to eachother. As described previously, detailed geological models of fluiddeposits are not typically available a-priori. Seismic surveys do nothave a high enough resolution and are not as sensitive to types ofdeposits that may cause a steam break-through. The delineations that arelogged with wireline and cored wells may be available but this data isnot contiguous and may not be used to interpolate in between wells. Thelocalizing and measuring embodiments disclosed in FIG. 2 provide greateraccuracy for later optimization of production.

FIG. 2 shows a well 200 (e.g., producer or injector) drilled through ageological formation 210 and a deposit layer 211. The deposit layer 211may include a low resistivity fluid deposit 205.

An EM tomography measurement embodiment 201 is shown. This embodimentmay include both a transmitter 230 and receiver 231 on the surface, thetransmitter 230 on the surface and the receiver 232 in the well 200, thetransmitter 232 in the well and the receiver 231 on the surface, or thetransmitter in one wellbore while the receiver is in another wellbore.

FIG. 2 further shows an LWD deep resistivity reading sensor tool 202 inthe drill string. The tool incorporates a multi-frequency, deep-reading,azimuthal (directional) resistivity sensor that may incorporate tiltedreceiver coils. The LWD deep resistivity sensor tool 202 may providemeasurements of approximately 20 feet from the well 200. The LWD tool202 may also be used in an LWD ultra-deep resistivity reading embodiment(e.g., >approximately 20 feet).

A current leakage measurement 203 embodiment is illustrated in relationto the well 200. As discussed subsequently, this embodiment measures thecurrent leakage on one of the pipes to map out the location and shape ofthe deposits 205.

FIG. 3 is a flowchart showing an embodiment of the method forlocalization using electromagnetic (EM) tomography or resistivitymeasurements, according to various examples. This embodiment may use EMtomography transmitter/receivers or an EM resistivity LWD tool (e.g.,azimuthal, non-azimuthal, deep reading, or ultra-deep reading) toperform EM tomography or EM resistivity measurements.

In block 301, the producer well or injector well is drilled 301 as shownin FIG. 2. In block 303, the EM tomography transmitters/receivers or EMresistivity LWD tool may then be used.

EM tomography measurement may be performed from surface to wellbore,wellbore to another wellbore, or surface to surface. It may be performedas a single-shot measurement or a time-lapse measurement. EM tomographymeasurements may employ an array of transmitting antennas and receivingantennas which may be of magnetic dipole, electric dipole or electricmonopole type. These transmitters and receivers may be towed on trucks,ships or sub-sea vehicles depending on the type of operatingenvironment.

In EM tomography, a single frequency, multi-frequency or pulsedelectromagnetic signal is transmitted from the transmitter into thesubterranean formations. Diffused and scattered signals, resulting fromthe transmitted signal, are received from the formation by thereceivers. The received electric and/or magnetic fields or voltages arepartly indicative of the characteristics of the downhole formations,specifically the resistivity of the layers.

The EM tomography measurements may be used to calculate the position ofdeposits at various depths (e.g., 0-6000 feet). EM tomography may beused if deposits are relatively large in volume and conductivitycontrast. Localization of deposits with the EM tomography method maybegin with an initial estimate of the underlying formation layers. Thisenables the system to resolve the layers easily and focus on thedeposits.

LWD azimuthal resistivity tools may also be used to map out thedeposits. LWD azimuthal resistivity tools may make multiple measurementsof resistivity at different azimuthal orientations relative to thewellbore as the tool rotates with the natural rotation of the drilling.The deep reading tool may be used in measuring deposits having ashallower nature (e.g., up to 20 feet range relative to wellbore) toenable operators to map out the resistivity of the reservoir sectionthat is local to the resistivity tool position.

In one embodiment, an azimuthal resistivity tool may be used. However,another embodiment may use a non-azimuthal tool if a relative directionof the observed deposit is not needed.

The LWD tool may be placed in the drill string of the producer welland/or the injector well. The resistivity logging data may then becollected at one or more depths as the drilling continues. Deposits maybe identified from unexpected deviations of the tool responses as thehorizontal drilling commences. They can also be identified from distanceto bed boundary inversions that can be conducted at different points.Ultra-deep reading tools may be used to map deposits up to 100 feet awayfrom the borehole.

FIG. 4 is a flowchart showing an embodiment of the method forlocalization using current leakage measurement, according to variousexamples. This embodiment may be used from one of the casings (e.g.,producer or injector) to map out the relative location and shape of thedeposits with respect to the wellbore used.

In the interest of clarity, the following method is described withrespect to the current being injected on the producer well casing.However, the terms “producer” and “injector” wells may be swapped andthe method would still operate as described.

In block 401, casing is placed in the producer well. In block 403,drilling of the injector well is begun. A current may then be injectedon the producer well casing, in block 405, from an electrode that isconnected to the wellhead. As the current moves down in the casing inthe wellbore, it leaks out to the geological formation. The leakage ateach depth is proportional to the local resistivity at that region andnear-by zones. Any near-by low resistivity deposit causes the currentleak to increase. The leakage difference along the casing may used as anindication of the presence of a near-by deposit.

In block 407, the current may be detected in the injector well casingusing a ranging tool on an injector well drill string. The current maybe calculated on the producer well at the present measure depth in block409. This calculated current is subtracted from a past depth currentmeasurement in order to calculate the current leakage in block 411.

Two different operations 413, 415 may be performed as a result ofdetermining the current leakage. In one embodiment (i.e., block 413),the calculated current leakage may be combined with EM resistivity LWDtool data to obtain an improved image of the deposit. In anotherembodiment (i.e., block 415), the calculated current leakage indicates azone of low resistivity. Such a zone may be indicative of a lowresistivity fluid deposit.

Effect of resistivity variations may be removed from the calculations byusing well planner software that can simulate an expected current leakgiven a well path and geology information but without the deposits.Since the producer well is typically placed at a fixed distance withrespect to near-by formation layers (through practice of geo-steering),changes in the leakage correlate well with the low resistivity deposits.

The current leakage may be measured using any one of a plurality ofembodiments that use a measurement of the current at each depth as thefirst step. One embodiment may employ current injection on the producer,and LWD magnetic field measurements during the drilling of the injector.In this case, the magnetic field measurements are directly proportionalto the current on the producer at the section that is closest to themagnetic field measurement tool in the injector. This may be illustratedin equation (1) as:

$\begin{matrix}{\overset{\_}{H} = {\frac{I}{2\pi\; r}\hat{\phi}}} & (1)\end{matrix}$where H is the magnetic field vector, I is the current on the pipe, r isthe shortest distance between the receivers and the pipe and ϕ is avector that is perpendicular to both z axis of the receiver and theshortest vector that connects the pipe to the receivers.

The relationship of equation (1) assumes constant casing current alongthe casing. However, this embodiment may be extended to any currentdistribution by using an appropriate electromagnetic model. This modeland configuration may be employed by the ranging tools to place theinjector well at fixed distance and direction with respect to theproducer well. As a result, a ranging tool may be used for the dualpurpose of well placement and also mapping of the deposits. In thisconfiguration, gradient measurements from the ranging tool can be usedto measure the distance and absolute magnetic field measurement so thatthe measured distance can be used to calculate the current.

FIG. 5 is a flowchart showing another embodiment of the method forlocalization using current leakage measurement, according to variousexamples. In this embodiment, the current is injected in the producerand/or the injector and the electrodes are placed in the well wherecurrent is injected.

In block 501, drilling of the producer well is started and, in block503, well casing is placed in at least a portion of the wellbore. Atleast two injection electrodes may be placed at various measurementdepths of the producer casing, in block 505. The electrodes are axiallyseparated by a distance along the casing that is fixed mechanically andboth electrodes are kept in touch with the casing.

In block 507, the voltage between two measure electrodes is measured ateach depth. These measure electrodes may be chosen individually the samewith or different to the injection electrodes. The voltage between themeasure electrodes is directly proportional to the current on the pipebetween the electrodes, and it can be used in the estimation. This isbased on ohm's law:

$\begin{matrix}{I = \frac{V}{R}} & (2)\end{matrix}$where V is the voltage between the electrodes, R is the resistancebetween the measure electrodes and I is the calculated current. In block509, the current I may be calculated on the producer well at eachmeasured depth.

Resistance R can be calculated from well plan or it can be measured byinjecting a known current between the injection electrodes and measuringthe voltage between the measure electrodes. If deposits are detectedthrough the monitoring of variations in the current leak, the accuracyof the R parameter is not as important since it is only a multiplicationfactor.

In block 511, the current calculated at the present depth is subtractedfrom a past current that was calculated at the past depth to determinethe current leakage between the present and past depths. This calculatedleakage may be used in two ways. In block 513, the calculated leakage iscombined with an EM resistivity LWD tool data to obtain an improvedimage of the deposit. In another embodiment (block 515), the currentleakage may be used as an indication of a low resistivity zone.

FIG. 6 is a flowchart showing another embodiment of the method forlocalization using current leakage measurement, according to variousexamples. This embodiment uses an azimuthal magnetic field from apermanent magnet sensor placed outside of the wellbore duringconstruction.

In block 601, drilling of the producer well is started and, in block603, well casing is placed in at least a portion of the wellbore. Theazimuthal magnetic sensor is then placed outside of the casing in block605. The magnetic field measurements are directly proportional to thecurrent at the section of the pipe that is closest to the magnetic fieldsensor. Using equation (1), this embodiment solves for the unknowncurrent using the measured magnetic field and distance from the sensorto the center of the casing.

In block 607, the current may be calculated on the producer well at eachmeasured depth. In block 609, the current calculated at the presentdepth is subtracted from a past current that was calculated at the pastdepth to determine the current leakage between the present and pastdepths. This calculated leakage may be used in two ways. In block 611,the calculated leakage is combined with an EM resistivity LWD tool datato obtain an improved image of the deposit. In another embodiment (block613), the current leakage may be used as an indication of a lowresistivity zone.

FIG. 7 is a flowchart showing another embodiment of the method forlocalization using current leakage measurement, according to variousexamples. This embodiment uses a radial electric field sensor

In block 701, drilling of the producer well is started and, in block703, well casing is placed in at least a portion of the wellbore. Theradial electric field sensor is then placed outside of the casing inblock 705. The radial electric field is directly proportional to currentleakage and can provide a direct estimation of the location of adeposit.

In block 707, the current may be calculated on the producer well at eachmeasured depth. In block 709, the current calculated at the presentdepth is subtracted from a past current that was calculated at the pastdepth to determine the current leakage between the past and presentdepths. This calculated leakage may be used in two ways. In block 711,the calculated leakage is combined with an EM resistivity LWD tool datato obtain an improved image of the deposit. In another embodiment (block713), the current leakage may be used as an indication of a lowresistivity zone.

In the embodiments of FIGS. 4-6, the leakage current between two pointson the casing may be calculated through a simple subtraction of twocurrents along the well at those two points. In practice, if the pointsare chosen to too close, accuracy of the current leakage estimate maynot be as accurate as more distant points since only a very smallcurrent is being probed. If the points are chosen too far, theresolution of the leakage measurement may become too low (which is inthe order of the distance between the two electrodes). As a result,there is an optimal distance when both criteria are met. The optimaldistance may vary with the resistivity of the formation and deposits,but it may be in a range between 1 foot and 50 feet.

The low resistivity fluid deposits may also be located through acousticlogging tools or borehole seismic methods through reflections or radialprofiling applications. If deposits intersect the wellbore, a boreholeimaging or coring method may be employed to collect more diverse dataabout the deposits.

FIG. 8 is a cross-sectional diagram showing a geological formation withan embodiment of an SAGD steam chamber, according to various examples.The SAGD method may be used in combination with the various optimizationembodiments discussed subsequently with reference to FIGS. 9-13. TheSAGD method is shown for purposes of illustration only as otherproduction methods may be used.

In this embodiment, the producer well 801 and injector well 802 aredrilled through the geological formation 800 and into a deposit layer811. Steam is then injected from the injector well 802. The steam formsa steam chamber 810 around the producer well 801.

The steam of the steam chamber 810 decreases the viscosity of anyhydrocarbons in the deposit layer 811. This may increase the mobility ofthe hydrocarbons.

In another embodiment, heat may be applied through resistive meanslocated in the injector well 802. This heat may also form the steamchamber 810 from any adjacent water. As the steam chamber 810 expands,the two wells 801, 802 are connected hydro-dynamically. The steamdistribution around the wells 801, 802 is typically not uniform and mayvary based on the geological and petrophysical properties of the rocks.

Embodiments of the production optimization method are shown in FIGS.9-11. These embodiments use geosteering, completion parameteroptimization, or steam characteristics estimation. The embodiments areapplied after localization of the deposits using one of the localizationembodiments described previously.

FIG. 9 is a flowchart showing an embodiment of a method for optimizingproduction of a fluid deposit, according to various examples. Thisembodiment uses geosteering as illustrated in FIG. 12.

The deposits are located and measured in block 901. Embodiments forperforming this step have been discussed previously.

In block 903, the drilling of the producer or injector wells aregeosteered based on deposit position, shape, and/or resistivity aspreviously described. The geosteering may be performed in one or more ofthe steps in blocks 905, 907, 909. For example, in block 905, thedrilling of the producer well is geosteered away from the deposits. Inblock 907, the drilling of the injector well is geosteered away from thedeposits. In block 909, the steam chamber design is geosteered away fromthe deposits.

FIG. 10 is a flowchart showing another embodiment of the method foroptimizing production of the fluid deposit. This embodiment adjusts oneor more completion parameters.

After the deposits are located and measured in block 1001, one or moreof the completion parameters may be adjusted based on the depositrelative position, shape, and/or resistivity, as seen in block 1003.

Examples of the completion parameters may include adjusting local slotsand/or seams of the casing based on nearby deposits, as seen in block1005. Another example, in block 1007, includes adjusting the slot and/orseam density and/or size based on nearby deposits. In yet anotherexample, in block 1009, fewer or no slots and/or seams may be used neardeposits. In another example, in block 1011, more slots and/or seams maybe used near deposits.

FIG. 11 is a flowchart showing another embodiment of the method foroptimizing production of the fluid deposit, according to variousexamples. This embodiment uses a steam chamber model to estimate steamcharacteristics of the deposit.

In block 1101, the deposits are located 1101. In block 1103, the depositdata from the localizing operation is fed into a steam chamber model toestimate the deposit's steam characteristics and/or productioncharacteristics.

FIG. 12 is a cross-sectional view of a geological formation in which ageosteering embodiment of the optimization method is used around adeposit, according to various examples. In this embodiment, the producerand injector wells 1200, 1201 are steered 1202, 1203 away from the lowresistivity deposit 1230 but still within the high production zones inthe reservoir 1209.

The geosteering may be accomplished by adjusting the vertical orhorizontal placement of the wells 1200, 1201. The freedom ofoptimization in the vertical direction may be limited due to a limitedsize of the reservoir in the vertical direction. Producer and injectorwell 1200, 1201 placement may be optimized individually. Alternatively,the wells 1200, 1201 may be optimized jointly through the use of a steamchamber model that can produce an estimate of the production amountbased on the placement of the wells 1200, 1201 with respect to near-byformation layers and deposits. The ideal positioning that optimizes theproduction is planned. Geosteering and operational limitations (e.g.,maximum dogleg) may also be applied as a constraint in the optimization.

The optimization of production and localization of deposits can takeplace simultaneously. For example, as a well is drilled, an LWD tool mayprovide data that can localize the deposits. This information may thenbe used in real time to determine the ideal well path that is executedthrough geosteering. In the new well path, LWD tools collect new dataand this process may be repeated. In this embodiment, this optimizationmay lead to different distances between the producer well and theinjector well as a function of the presence of nearby deposits.

FIG. 13 is a cross-sectional view of a geological formation in whichvarious casing embodiments of the optimization method are used near adeposit, according to various examples. This embodiment may use thedensity and/or distribution of the slots and/or seams of the casing toaccommodate the localized deposits.

FIG. 13 shows producer and injector wells 1310, 1311 that each havecasings/liners. The casings include varying densities of slots and/orseams 1320-1326 depending on the locations of the deposits 1300, 1301.For example, fewer or no slots and/or seams may be placed in areas withnearby deposits so that steam can be focused on the areas whereproduction can be increased. An opposite strategy may also be used touse more (or wider) slots and seams in areas with deposits to compensatefor the loss of steam in the desired volume. Determination of whichstrategy to use can be made based on a steam chamber hydro-dynamic andpetrophysical model.

FIG. 14 is a diagram showing a wireline system 1464 and FIG. 15 is adiagram showing a drilling rig system 1564, according to variousexamples. The systems 1464, 1564 may thus comprise portions of awireline logging tool body 1420 as part of a wireline logging operationor of a down hole tool 1524, including the EM tomography or LWD EMresistivity tools described previously, as part of a down hole drillingoperation.

FIG. 14 illustrates a well that may be used as either an injector wellor a producer well. In this case, a drilling platform 1486 is equippedwith a derrick 1488 that supports a hoist 1490.

Drilling oil and gas wells is commonly carried out using a string ofdrill pipes connected together so as to form a drillstring that islowered through a rotary table 1410 into a wellbore or borehole 1412.Here it is assumed that the drillstring has been temporarily removedfrom the borehole 1412 to allow a wireline logging tool body 1420 to belowered by wireline or logging cable 1474 (e.g., slickline cable) intothe borehole 1412. Typically, the wireline logging tool body 1420 islowered to the bottom of the region of interest and subsequently pulledupward at a substantially constant speed.

During the upward trip, at a series of depths various instruments may beused to perform measurements on the subsurface geological formations1414 adjacent to the borehole 1412 (and the tool body 1420). Thewireline data may be communicated to a surface logging facility 1492 forprocessing, analysis, and/or storage. The logging facility 1492 may beprovided with electronic equipment for various types of signalprocessing. Similar formation evaluation data may be gathered andanalyzed during drilling operations (e.g., during LWD/MWD operations,and by extension, sampling while drilling). The data may be used forlocalizing and measuring the deposits as previously described.

In some embodiments, the tool body 1420 is suspended in the wellbore bya wireline cable 1474 that connects the tool to a surface control unit(e.g., comprising a workstation 1454). The tool may be deployed in theborehole 1412 on coiled tubing, jointed drill pipe, hard wired drillpipe, or any other suitable deployment technique.

Referring to FIG. 15, it can be seen how a system 1564 may also form aportion of a drilling rig 1502 located at the surface 1504 of a well1506. The drilling rig 1502 may provide support for a drillstring 1508.The drillstring 1508 may operate to penetrate the rotary table 1410 fordrilling the borehole 1412 through the subsurface formations 1414. Thedrillstring 1508 may include a drill pipe 1518 and a bottom holeassembly 1520, perhaps located at the lower portion of the drill pipe1518.

The bottom hole assembly 1520 may include drill collars 1522, a downhole tool 1524, and a drill bit 1526. The drill bit 1526 may operate tocreate the borehole 1412 by penetrating the surface 1504 and thesubsurface formations 1414. The down hole tool 1524 may comprise any ofa number of different types of tools including MWD tools, LWD tools, andothers.

During drilling operations, the drillstring 1508 (perhaps including thedrill pipe 1518 and the bottom hole assembly 1520) may be rotated by therotary table 1410. Although not shown, in addition to, or alternatively,the bottom hole assembly 1520 may also be rotated by a motor (e.g., amud motor) that is located down hole. The drill collars 1522 may be usedto add weight to the drill bit 1526. The drill collars 1522 may alsooperate to stiffen the bottom hole assembly 1520, allowing the bottomhole assembly 1520 to transfer the added weight to the drill bit 1526,and in turn, to assist the drill bit 1526 in penetrating the surface1504 and subsurface formations 1414.

During drilling operations, a mud pump 1532 may pump drilling fluid(sometimes known by those of ordinary skill in the art as “drillingmud”) from a mud pit 1534 through a hose 1536 into the drill pipe 1518and down to the drill bit 1526. The drilling fluid can flow out from thedrill bit 1526 and be returned to the surface 1504 through an annulararea 1540 between the drill pipe 1518 and the sides of the borehole1412. The drilling fluid may then be returned to the mud pit 1534, wheresuch fluid is filtered. In some embodiments, the drilling fluid can beused to cool the drill bit 1526, as well as to provide lubrication forthe drill bit 1526 during drilling operations. Additionally, thedrilling fluid may be used to remove subsurface formation cuttingscreated by operating the drill bit 1526.

The workstation 1454 and the controller 1496 may include modulescomprising hardware circuitry, a processor, and/or memory circuits thatmay store software program modules and objects, and/or firmware, andcombinations thereof. The workstation 1454 and controller 1496 may beconfigured to control the direction and depth of the drilling in orderto geosteer the drilling as discussed previously. For example, in someembodiments, such modules may be included in an apparatus and/or systemoperation simulation package, such as a software electrical signalsimulation package, a power usage and distribution simulation package, apower/heat dissipation simulation package, and/or a combination ofsoftware and hardware used to simulate the operation of variouspotential embodiments.

Additional embodiments may include:

Example 1 is a method for optimizing production in a well, the methodcomprising: localizing low resistivity fluid deposits in a geologicalformation; and optimizing production of the fluid deposits from thegeological formation based on the localizing by adjustment of at leastone of a drilling parameter or a production parameter.

In Example 2, the subject matter of Example 1 can further includewherein localizing comprises electromagnetic tomography using atransmitter on a surface of the geological formation and a receiver in aborehole through the geological formation.

In Example 3, the subject matter of Examples 1-2 can further includewherein localizing comprises electromagnetic tomography using atransmitter in a borehole through the geological formation and areceiver on a surface of the geological formation.

In Example 4, the subject matter of Examples 1-3 can further includewherein localizing comprises electromagnetic tomography using atransmitter and receiver on a surface of the geological formation.

In Example 5, the subject matter of Examples 1-4 can further includewherein localizing comprises using an azimuthal resistivity tool.

In Example 6, the subject matter of Examples 1-5 can further includewherein using the azimuthal resistivity tool comprises measuring acurrent leakage from a casing through the geological formation.

In Example 7, the subject matter of Examples 1-6 can further includewherein the casing is a production well casing and measuring the currentleakage comprises: injecting a current on the production well casing;and measuring a magnetic field within an injector well.

In Example 8, the subject matter of Examples 1-7 can further includewherein the casing is a production well casing and/or an injector wellcasing and measuring the current leakage comprises: injecting a currenton the production casing and/or the injector casing; and measuring themagnetic field within the casing on which the current is injected.

In Example 9, the subject matter of Examples 1-8 can further includewherein measuring the current leakage comprises: measuring the magneticfield from magnetic sensors located outside of well casing.

In Example 10, the subject matter of Examples 1-9 can further includewherein optimizing production comprises geosteering a drill head.

In Example 11, the subject matter of Examples 1-10 can further includewherein optimizing production comprises adjusting slots and/or seams ina casing of a production well.

In Example 12, the subject matter of Examples 1-11 can further includewherein adjusting the slots and/or seams in the casing comprises atleast one of: adjusting the slot and/or seam design based on the fluiddeposit and/or adjusting the slot and/or seam density and/or size basedon the fluid deposit.

In Example 13, the subject matter of Examples 1-12 can further includewherein optimizing production comprises estimating steam characteristicsand/or production characteristics of the fluid deposit.

Example 14 is a method for optimizing production in a well, the methodcomprising: drilling a production or an injector well in a geologicalformation; localizing, with the production or injector well, lowresistivity fluid deposits in the geological formation by:electromagnetic tomography, current leakage measurement, or loggingwhile drilling deep-reading to map low resistivity fluid deposits in thegeological formation; and geosteering drilling, adjusting casingparameters, or estimating steam characteristics of the fluid based onthe localizing.

In Example 15, the subject matter of Example 14 can further includewherein the geosteering drilling comprises geosteering a drill bit inthe production well in three dimensions through the geologicalformation.

In Example 16, the subject matter of Examples 14-15 can further includewherein localizing fluid deposits in the geological formation comprisesusing a logging while drilling tool.

Example 17 is a drilling system comprising: a down hole tool comprisingan electromagnetic tomography tool, a current leakage measurement tool,or a logging while drilling deep-reading too configured to map lowresistivity fluid deposits in a geological formation; and a controllercoupled to the down hole tool and configured to control optimization ofproduction of the fluid by controlling a drilling parameter or aproduction parameter based on the mapping of the fluid.

In Example 18, the subject matter of Example 17 can further includewherein the down hole tool comprises a logging while drilling toolhaving a non-azimuthal, azimuthal, deep-reading, or ultra-deep readingfunction.

In Example 19, the subject matter of Examples 17-18 can further includewherein the controller is further configured to control geosteering of adrill string based on the mapping of the fluid.

In Example 20, the subject matter of Examples 17-19 can further includewell casing in an injector well wherein the well casing comprises a slotor seam design in response to the mapping of the fluid.

In Example 21, the subject matter of Examples 17-20 can further includewherein the slot or seam design includes density and/or locations ofslot and/or seams of the well casing.

In Example 22, the subject matter of Examples 17-21 can further includewherein the controller is further configured to steer a steam chamberaway from the fluid.

The accompanying drawings that form a part hereof, show by way ofillustration, and not of limitation, specific embodiments in which thesubject matter may be practiced. The embodiments illustrated aredescribed in sufficient detail to enable those skilled in the art topractice the teachings disclosed herein. Other embodiments may beutilized and derived therefrom, such that structural and logicalsubstitutions and changes may be made without departing from the scopeof this disclosure. This Detailed Description, therefore, is not to betaken in a limiting sense, and the scope of various embodiments isdefined only by the appended claims, along with the full range ofequivalents to which such claims are entitled.

What is claimed is:
 1. A method for optimizing production in a well, themethod comprising: localizing low resistivity fluid deposits in ageological formation based on calculation of a difference between twoelectric current values, where each of the two electric current valuescorrespond to different depths in the well: and optimizing production ofthe fluid deposits from the geological formation based on the localizingby adjustment of at least one of a drilling parameter or a productionparameter.
 2. The method of claim 1, wherein localizing compriseselectromagnetic tomography using a transmitter on a surface of thegeological formation and a receiver in a borehole through the geologicalformation.
 3. The method of claim 1, wherein localizing compriseselectromagnetic tomography using a transmitter in a borehole through thegeological formation and a receiver on a surface of the geologicalformation.
 4. The method of claim 1, wherein localizing compriseselectromagnetic tomography using a transmitter and receiver on a surfaceof the geological formation.
 5. The method of claim 1, whereinlocalizing comprises using an azimuthal resistivity tool.
 6. The methodof claim 5, wherein using the azimuthal resistivity tool comprisesmeasuring a current leakage from a casing through the geologicalformation.
 7. The method of claim 6, wherein the casing is a productionwell casing and measuring the current leakage comprises: injecting acurrent on the production well casing; and measuring a magnetic fieldwithin an injector well.
 8. The method of claim 6, wherein the casing isa production well casing and measuring the current leakage comprises:injecting a current on the production casing; and measuring the magneticfield within the production casing on which the current is injected. 9.The method of claim 6, wherein measuring the current leakage comprises:measuring the magnetic field from magnetic sensors located outside ofwell casing.
 10. The method of claim 1, wherein optimizing productioncomprises geosteering a drill head.
 11. The method of claim 1, whereinoptimizing production comprises adjusting slots or seams in a casing ofa production well.
 12. The method of claim 11, wherein adjusting theslots or seams in the casing comprises at least one of: adjusting theslot or seam design based on the fluid deposit, adjusting the slot orseam density based on the fluid deposit, and adjusting the slot or seamsize based on the fluid deposit.
 13. The method of claim 1, whereinoptimizing production comprises estimating at least one of steamcharacteristics and production characteristics of the fluid deposit. 14.The method of claim 1, wherein the difference between two electriccurrent values is a given current value and wherein localizing lowresistivity fluid deposits comprises injecting a first current on aproduction well casing; detecting a second current on an injector wellcasing; and calculating the given current value, wherein the givencurrent value is associated with the production well casing.
 15. Amethod for optimizing production in a well, the method comprising:drilling a production or an injector well in a geological formation;localizing, with the production or injector well, low resistivity fluiddeposits in the geological formation based on calculation of adifference between two electric current values, where each of the twoelectric current values correspond to different depths in the productionor injector well by: electromagnetic tomography, current leakagemeasurement, or logging while drilling deep-reading to map lowresistivity fluid deposits in the geological formation; and geosteeringdrilling, adjusting casing parameters, or estimating steamcharacteristics of the fluid based on the localizing.
 16. The method ofclaim 15, wherein the geosteering drilling comprises geosteering a drillbit in the production well in three dimensions through the geologicalformation.
 17. The method of claim 15, wherein localizing fluid depositsin the geological formation comprises using a logging while drillingtool.
 18. The method of claim 15, wherein the difference between twoelectric current values is a given current value and wherein localizinglow resistivity fluid deposits comprises injecting a first current on aproduction well casing; detecting a second current on an injector wellcasing; and calculating the given current value, wherein the givencurrent value is associated with the production well casing.
 19. Adrilling system comprising: a down hole tool comprising anelectromagnetic tomography tool, a current leakage measurement tool, ora logging while drilling deep-reading tool configured to map lowresistivity fluid deposits in a geological formation based oncalculation of a difference between two electric current values, whereeach of the two electric current values correspond to different depthsin a well: and a controller coupled to the down hole tool and configuredto control optimization of production of the fluid by controlling adrilling parameter or a production parameter based on the mapping of thefluid.
 20. The system of claim 19, wherein the down hole tool comprisesa logging while drilling tool having a non-azimuthal, azimuthal,deep-reading, or ultra-deep reading function.
 21. The system of claim19, wherein the controller is further configured to control geosteeringof a drill string based on the mapping of the fluid.
 22. The system ofclaim 19, further comprising a well casing in an injector well whereinthe well casing comprises a slot or seam design in response to themapping of the fluid.
 23. The system of claim 22, wherein the slot orseam design includes at least one of density, locations of slot, andseams of the well casing.
 24. The system of claim 19, wherein thecontroller is further configured to steer a steam chamber away from thefluid.
 25. The drilling system of claim 19, wherein the differencebetween two electric current values is a given current value and whereinlocalizing low resistivity fluid deposits comprises injecting a firstcurrent on a production well casing; detecting a second current on aninjector well casing; and calculating the given current value, whereinthe given current value is associated with the production well casing.